Carbon dioxide (CO2) geological storage is one of the approaches considered for stabilizing atmospheric CO2 concentrations. Captured CO2 from a source such as coal-fired power plant flue gas is injected through a well into the subsurface, e.g. saline aquifers, where it is likely to be at supercritical conditions. Once injected, CO2 is expected to be geologically confined by impermeable layers overlaying the reservoir thereby enabling long-term (thousands of years) interactions to occur between water, minerals, and CO2 to form solubilised CO2, carbonic acid and immobile carbonates.
The volumetric storage capacity of saline aquifers has been determined to be quite large (See Holloway, S. “An overview of the Joule II project: The underground disposal of carbon dioxide.” Energy Conversion and Management, 38, p193-p198 (1997) and Gunter, W. D., Wong, S., Cheel, D. B. & Sjostrom, G. “Large CO2 Sinks: Their role in the mitigation of greenhouse gases from an international, national (Canadian) and provincial (Alberta) perspective”. Applied Energy, 61, 209-227 (1998)); and it is thought to be between 20% and 500% of the cumulative worldwide projected CO2 emissions through 2050 (See Davidson, J., Freud, P. & Smith, A. “Putting Carbon Back in the ground”. IEA Greenhouse Gas R&D Program, February 2001). Therefore, with proper site selection and management, geological CO2 storage may play a major role in reducing atmospheric CO2 accumulation. However, several key issues need to be resolved before large-scale geological CO2 sequestration becomes feasible. First, accurate predictions of the evolution of the spatial extent of the CO2 are necessary for safe and secure storage site selection. Second, it is expected that continuous monitoring of the CO2 plume within a saline aquifer resulting from injection may be required.
CO2 displacement within a saline aquifer is governed by spatially varying parameters such as porosity, permeability and its anisotropy, and brine salinity. Additionally, saturation dependent properties affecting displacement are capillary pressure and relative permeabilities. The latter themselves are characterized by residual water and CO2 saturations. Frequently, geological and petrophysical data proximate a well are unavailable, and as a result regional data are used to build synthetic site-specific geological horizons, and to provide petrophysical characterization. These synthetic data sets are usually obtained by interpolation between existing wells, e.g. kriging (See A. G. Journel and Ch. J. Huijbregts. “Mining Geostatistics”, The Blackburn Press, 1978).
Predictive reservoir simulations, based upon which decisions are routinely made, are rarely definitive. More often than not, data are either sparse, or of such a low resolution and of a low information content that uncertainties in the outcomes must be estimated. For carbon sequestration, uncertainty quantification is even more important than in the oilfield because of potential requirements and anticipated regulations on containment. For example, failure to properly quantify the vertical movement of the CO2 plume could result in leakage into the atmosphere or into potable water supplies. Similarly, failure to properly quantify the radial movement of the plume could result in movement into uncapped wells or into property that was not leased or acquired for sequestration.
Therefore, at every stage of a CO2 sequestration project, performance and risk metrics such as containment, injectivity, and displacement efficiency, are important assessments that should be used in decision-making. To a large extent, expectations in performance metrics and their uncertainty quantification, depend on the petrophysical characterization of the storage site. Site characterization is normally conducted from the very early stages of the project and refined continuously as more data become available.
By nature, well-known geostatistical methods should rely upon large amounts of statistical information with regard to both single and multiphase flow properties of the rock within a given lithology. Unfortunately, whilst single-phase flow behavior may be estimated over large numbers of samples, multiphase flow properties are time consuming to acquire and are error prone even in the laboratory. Furthermore, procuring formation samples along a given lithology away from a wellbore is prohibitive.
It is for the above-mentioned reasons that it is important to have a reasonable basis for incorporating statistical inputs that are based on petrophysical sciences, and which honor log and seismic data within the context of their own measurement specifications. It is also desirable that these methods are able to construct two-phase flow properties and their statistical variation at all locations of relevance. Geostatistical methods are ill-suited for this purpose, because of i) unavailability of statistics away from the wellbore, and ii) impracticality of acquiring the data required to carry out predictive multiphase flow calculations. (See Busby D., Feraille M., Romani T., Touzani S. “Method for evaluating an underground reservoir production scheme taking account of uncertainty”. U.S. Patent Application 2009/0043555 A1, see H. E. Klumpen, S. T. Raphael, R. I. Torrens, G. Nunez, W. J. Bailey, B. Couet, “System and Method for Performing Oilfield Simulation”, U.S. Patent Application 2008/0133194 A1; see B. Raghuraman, B. Couet. “Tools for decision-making in reservoir risk management”, U.S. Pat. No. 7,512,543, see I. Bradford, J. M. Cook, J. Fuller, W. D. Aldred, V. Gholkar. “Method for updating an earth model using measurements gathered during borehole construction”, U.S. Pat. No. 6,766,254; and see T. A. Jones, S. J. Helwick, Jr. “Method of generating 3-D geologic models incorporating geologic and geophysical constraints”, U.S. Pat. No. 5,838,634).
From the onset of a CO2 sequestration project, a variety of metrics related to containment (or migration), displacement efficiency, and injectivity dictate decision-making. Expected values of the performance metrics and their variance need to be considered in the process, and a well-defined methodology is needed. The method of the invention overcomes the limitations of the prior art and provides an avenue for computing statistical measures of performance metrics related to containment and displacement characteristics.